February 26, 2015

By November 2014, according to FT Alphaville’s Izabella Kaminska, formerly a producer at CNBC, a natural gas reporter at Platts and an associate editor of BP’s internal magazine, the unanticipated over-production of ultra-sweet, light crude oil in the United States has resulted in market oversupply at a time when refineries had invested “huge sums of money”to develop highly complex refineries with coker units capable of processing cheap inferior crudes just as efficiently as light sweet grades (Kaminska 2014).”

Ongoing controversies surrounding the construction of inter-provincial and international pipelines to transport bitumen from the oil sands have raised questions about the reasons Canada does not develop an even more integrated value-added oil industry. By 2013 with profits soaring, there was a pulling back of taxation easing and a decrease in enthusiasm for what many perceive as subsidies for the oil industry. In the report entitled “Public Services for Ontarians: a Path to Sustainability and Excellence” by the Commission on the Reform of Ontario’s Public Services, committee chair, economist Don Drummond, lamented the lack of federal support for Ontario’s green energy initiatives, while the oil and gas sectors received $1.4 billion in annual subsidies. However, there is at the same time, an aggressive push towards relaxing environmental concerns to allow for expansion of the already impressive network of pipelines to expand markets for bitumen with a focus on Asia.

Hearings of the Northern Gateway Project Joint Review Panel Hearings, examining “the environmental viability of the proposed $6-billion twin pipeline project” were besieged by protesters who claimed the review was as undemocratic and alienating as observers watch the proceedings on screen in “dark and dreary rooms” separated from presenters in an effort to maintain order and respect. While the thousands of interveners protesting are successful in capturing media attention, there is a sense that pipeline expansion is inevitable as the oil industry and federal and Alberta governments align in their focus on increasing bitumen production and access to markets (west, east, south and even north). In 2012, faced with a boom in North American oil production, a shale and oil sands revolution and lack of pipeline capacity the very low price of WCS at $57 US a barrel suffered a 36% differential against WTI. With current North American crude oil markets, Mark Corey argued that once crude reaches tidewater, this waterborne crude will have higher value than landlocked crude. Getting tidewater access pricing point depends on increased pipeline access.

John Carruthers, President, Enbridge Northern Gateway Pipelines and Enbridge’s panel of well known energy economists including Calgarian Bob Mansell and Muse Consultants were cross-examined by Alberta Federation of Labour president Gil McGowan. McGowan argued that there would be increased job loss if 585,000 barrels of bitumen a day were exported to China rather than upgraded and refined in Canada. Mansell argued Alberta does not have strong, major consumer markets for refined products and there is therefore no market incentive for large-scale refining. The NDP leader is promoting pipelines to eastern Canadian refineries. A report Muse Consulting claims that as crude prices rise Canadian crude producers revenue increases but so does the cost of feedstock to Canadian refiners using western crude wherever they might be reducing the benefit of Canadian crude to Canadian refineries by about 25 per cent. (Pratt, Sheila. 2012-09-05. “Enbridge pipeline hearing focuses on economic benefits.” Edmonton Journal.)

“I sometimes hear speculation that the building of more Canadian refineries would lower the price of wholesale and retail fuels for Canadian consumers. It is important to understand, however, that Canadian refineries are really just part of a North American capacity pool, and lower wholesale prices in Canada brought about by more capacity would quickly attract U.S. wholesale buyers, thus negating any hopes of sustained lower prices in Canada (Ervin 2012-02).”

Standing Senate Committee on Energy, the Environment and Natural Resources tabled their report entitled “Now or Never” in which they recommended shipping crude oil from the west to the east of Canada:

<blockquote> “The committee also looks favourably upon the prospect of shipping western Canadian crude to the East for refining and marketing in Ontario,
Quebec, Atlantic Canada and international markets. This idea has long been touted as an obvious way to boost Eastern Canadian energy security and advance nation-building, but it has repeatedly been delayed because of inadequate market conditions. However, the economics for piping oil to the East have improved considerably, particularly because higher prices can be achieved for oil in Eastern Canada than in the American Midwest.” (Standing Senate Committee on Energy, the Environment and Natural Resources. July 2012. Now or Never: Canada Must Act Urgently to Seize its Place in the New Energy World Order. </blockquote>

For most of us it is confusing to attempt to follow the flow of crude oil through complicated networks of pipelines from north to south (or west to east) then back again as much more expensive, products refined in the United States? Or will be purchasing refined products from the eastern United States from refineries that process crude oil imported from Saudi Arabia, Africa and Venezuela? As China buys more of the oil sands and China and India complete their super refineries, will the gasoline in Canadian pumps will be coming from there, an even cheaper source than the United States? Does that mean bitumen from northern Alberta will traverse British Columbia/Alberta borders, then cross the ocean twice to return to us as refined products that cost less to the Canadian consumer and the environment? What are the guarantees that we will have access to oil and its byproducts in future markets when 40% of the oil sands industry is already foreign-owned and managed?

“According to the Canadian Energy Research Institute, as oil sands production grows, employment in Canada as a result of new oil sands investments in production and processing is expected to grow from 75,000 jobs in 2010 to 905,000 jobs in 2035, with 126,000 jobs being sourced in provinces other than Alberta. New oil sands development is expected to contribute more than $2.1 trillion (2010 dollars) to the Canadian economy over the next 25 years – about $84 billion per year. The oil sands industry will pay an estimated $766 billion in provincial and federal taxes and royalties in the same period, which contributes to quality of life and services across Canada (CAPP. 2011-09-22. “Oil sands a Canadian job creator; domestic and U.S. processing needed.” )”

Integrated firms, such as Calgary-based Husky (controlled by Hong Kong billionaire Li Ka-shing) with its crude storage system in Hardisty, pipelines, upgrader and refineries, use the cheaper oil sands crude oil as refinery and upgrader feedstock. The mitigation potential of integrated firms is substantial. Husky’s net earnings increased by 22% since April 2011 in spite of the volatility of price of crude. The Calgary-based American integrated company, Imperial Oil, with its refineries posted a 30% increase in earnings in the first quarter of 2012 (Calgary Herald 2012-04).

In North America, the benchmark crude oil price is West Texas Intermediate (“WTI”), a high-quality, light-weight, low-sulphur, sweet crude; WTI is the underlying commodity of the (NYME) New York Mercantile Exchange’s oil futures contracts. These properties make it excellent for making gasoline, which is why it is the major benchmark of crude oil in the Americas. WTI is generally priced at about a $5-6 per barrel premium to the OPEC Basket Price and about $1-2 per-barrel premium to Brent (Amadeo February 13, 2012).” Western Canadian Select (WCS) are priced/discounted against the the price of West Texas Intermediate (WTI) crude oil (http://www.baytex.ab.ca/operations/marketing/benchmark-heavy-oil-prices.cfm). According to reuters, in February 2013 WTI was at $93; WCS at $57 (a 36% discount) and Brent was $111 per barrel. In October 2012 WTI was at US$96.21 a barrel and WCS was at US$74.21 a $22.00 discount or differential which is 22.8%. (http://www.baytex.ab.ca/files/pdf/Operations/Historical%20WCS%20Pricing_October%202012.pdf) In December 18, 2012 WCS was $55 US per barrel with $33 US discount relative to WTI grade at $88 US. The world price for light sweet Brent Crude was just shy of $109 per barrel. (Kleiss, Karen. 2012-12-19. “Plunging oil price a long-term concern for Alberta.” Edmonton Journal). Lower prices, which are also related to seasonal events, are consistently tied to over supply and inadequate transportation infrastructure to suitable refineries.

As one question appears to be answered another is raised as issues concerning the oil industry cannot be disentangled from questions and concerns about complex financial instruments that have changed basic concepts of economics globally. Public policy regarding energy strategies needs to balance concerns about the economy in general, employment, transportation and the environment.

“[T]he government’s focus began to really sharpen in the mid-1990s in the wake of several significant accidents and the industry’s response […] of a broad commitment to risk management. The ebb and flow of legislative and regulatory mandates is directly tied to accidents, with the regulatory tide becoming ever higher when the accidents come in groups, as they did in 1994 and 1995, 2000 and 2001, and most recently, [in 2010].” Tenley, George. 2011-04-04/07. Opening Address. Managing Pipeline Integrity. 11th Workshop. Banff, AB.

How long will it take for greener energies to be developed gradually replacing our thirst for oil? How green will they really be? How deep are the changes you are willing to make? In the interim, how can we manage risks inherent in the energy industries?

Pipelines and/or refineries? What are the environmental costs for both?

What if there is an oil shortage or crisis?

“Can Canada replace the oil it imports with resources from its own territory if our suppliers become unreliable, or if an oil crisis becomes a reality? The answer is a resounding NO! Under NAFTA, we must keep sending the same proportion of our oil to the United States no matter what happens on the world stage. Article 605 of NAFTA only allows us to reduce exports to the U.S. if we cut our domestic supplies by the same proportion. Furthermore, we can’t charge the U.S. a higher price than the one
in Canada and we can’t disrupt or restrict the normal channels of supply. What are those normal channels? A huge network of 16,000 km of pipelines sends Canadian oil south, mainly to the American mid-west. At the moment, no pipeline takes Alberta’s oil to eastern Canada (Council of Canadians).”

According to most North American economists and the business community the the responsibility of the CEO’s of incorporated companies such as the oil sands giants, which include super major oil companies (who represent more than 80% of the oil sands production in Canada: BP Canada Energy Company (British multinational oil and gas company headquartered in London, United Kingdom), Canadian Natural Resources Limited, Cenovus Energy Inc., ConocoPhillips Canada Resources Corp. (American multinational energy), Devon Canada Corporation(largest U.S.-based independent natural gas and oil producer), Imperial Oil (controlled by US based ExxonMobil, which owns 69.6% of its stock), Nexen Inc., Shell Canada Energy(Canada-based subsidiary of Royal Dutch Shell, one of the largest multinational oil companies in the world), Statoil Canada Ltd., Suncor Energy Inc.(Canadian), Teck Resources Limited (Canadian), Total E&P Canada Ltd.)(French multinational oil and gas company, one of the six “Supermajor” oil companies in the world), the major players in the oil refining industry (Imperial Oil, Husky (controlled by Hong Kong billionaire Li Ka-shing) Harvest (controlled by state-owned Korea National Oil Corporation (KNOC), Chevron (American multinational energy corporation, one of six super majors), Suncor (Canadian), Shell (Canada-based subsidiary of Royal Dutch Shell, one of the largest multinational oil companies in the world), NOVA Chemicals, Ultramar (Canadian), Irving Oil (private Canadian) and the oil pipeline industry (TransCanada (Canadian), Enbridge (Canadian), Seaway), is to increase the market value of stocks owned by shareholders.

The Canadian Council of Chief Executives (CCCE) an influential public policy advocate association composed of the CEOs of 150 leading Canadian companies, CEOs, who “collectively administer C$4.5 trillion in assets, have annual revenues in excess of C$850 billion, and are responsible for the vast majority of Canada’s exports, investment, research and development, and training.” In 2012 they hosted a series entitled “Canada in the Pacific Century: Ensuring Canada’s Success in a Rebalanced Global Economy.” In the session in Calgary December, 2012 there was much celebratory congratulations on the federal decision to approve $15B Chinese takeover of Nexen. Alberta’s Energy Minister repeats again his call to get bitumen to tidewater or saltwater ports so Alberta can get “world price” instead of suffering increasing price differentials against WTI. Because Alberta is landlocked, not at tidewater, the oil industry loses $15 – $20 billion in revenues annually. He claims the lost oil revenue is reflected in lost provincial royalties although Alberta receives Bitumen Royalty-in-Kind (BRIK) by which the government has the option to take its royalty share either in cash or in kind. “Currently, the government takes its share of conventional crude oil production in kind and collects its royalty share for other resources in cash. The decision to exercise the in-kind option for bitumen was identified in October 2007 as a way for the Crown to use its share of bitumen strategically to supply potential upgraders and refineries in Alberta, and to optimize its royalty share by marketing those volumes (Government of Alberta. Energy. BRIK. FAQ).”.

Pipelines and/or refineries? What are the environmental costs for both?

Corrosion, poor planning and response

“The evolution of safety regulation in North America has moved to a new focus; namely, the total corporate responsibility for every facet of the operation, including the integrity management plan and the actions taken under it. This strong focus on the “management” side of “integrity management” has occurred over a relatively short timeframe, and has been made operational in the wake of serious industry sins of omission at the highest levels of corporate leadership.” Tenley, George. 2011-04-04/07. Opening Address. Managing Pipeline Integrity. 11th Workshop. Banff, AB.

Pipelines are aging. Newer pipelines can have monitoring devices built in but these new smart technologies are difficult to adapt to pipelines built 50 years ago. In its 2010 field surveillance report, the Energy Resources Conservation Board (ERCB), an independent agency of the Government of Alberta, recorded “687 pipeline failures across the province” (ERCB. 2011-11. ST57-2011 “Field Surveillance and Operations Branch Provincial Summary 2010” p. 16 http://www.ercb.ca/docs/products/STs/ST57-2011.pdf).” (626 were leaks/hits, 18 were ruptures, and 43 were hits with no release (ERCB 2010).

There is an intense race to add new lines, reverse flows and repair old pipelines as oil sands’ projects increase production. There are three major pipeline projects proposed in British Columbia: Enbridge’s Northern Gateway Pipeline, the expansion of Kinder Morgan’s Trans Mountain Pipeline, and the Pacific Trails Pipeline by Apache, Encana and EOG Resources. There is currently an over production of light and heavy Canadian crude varieties and a pipeline bottleneck in the American Midwest. Refineries are closed for maintenance or expediency and Canadian crude is steeply discounted against WTI (Calgary Herald 2012-04). There is also a heightened competition between Alberta’s oil sands and North Dakota’s Bakken formation “tight” oil for pipeline priorities. Oil refineries are costly to build and/or refurbish and the market is considered to be “mature.” International agreements appear to limit the ability of nation-states to make logical, reasonable decisions.

“One of the key barriers identified was the risk-averse nature of the [oil] industry. Unless industry is given a compelling reason to do so, such as fiscal or regulatory pressure from the government, companies are unlikely to invest in new refining capacity in the mature North American market. Rather, they will invest capital wherever in the world that returns are highest. According to industry, government will have to play an instrumental role if the vision is to be achieved (Laureshen, Clark and Du Plessis 2005:15).“

“In order to transport bitumen to refineries equipped to process it, bitumen must be blended with a diluent, traditionally condensate, to meet pipeline specifications for density and viscosity (NEB).” Dilbit: Growth in non-upgraded bitumen supply will increase the demand for diluent required to facilitate pipeline transportation to market. The Board’s outlook for traditional diluent (i.e., condensate) projects little growth in supply through to 2015, while demand under current operational conditions would be
expected to rise by approximately 50 000 m3 /d (315 mb/d). Additional supply could be made available by directing condensate used for other purposes to diluent usage, but the majority of the gap must be filled through the use of substitutes. Several opportunities exist for substitutes including refinery naphtha and conventional light oil; however, the most suitable solution, due to its availability, is synthetic crude oil (SCO) ( (NEB 2004:12).”

Pipelines: Internal Corrosion

“A chief concern about the transport of Canadian crude through the proposed Keystone XL pipeline is a claim that dilbit poses more release risks than other types of crude. In particular, the committee will examine whether there is evidence that dilbit has corrosive or erosive characteristics that elevate its potential for release from transmission pipelines when compared with other crude oils. Should the committee conclude there is no evidence of an increased potential for release, it will report this finding to the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) by spring 2013 (Institute for Corrosion Ohio University).”

“Pipeline integrity is an increasing challenge to the energy industry as the infrastructure is aging, and new field developments are introduced in both deep and remote areas of the world (source).”

Although the industry claims that diluted bitumen (dilbit) is no more corrosive than conventional crude, older pipelines are at higher risk because water that separates from dilbit tends to collect and start corroding (Linda Daugherty, US Pipeline and Hazardous Materials Safety Administration (PHMSA)’s deputy associate administrator for policy and programs).

“As a starting point, the committee might want to reference similar types of crudes,” suggested Linda Daugherty, US Pipeline and Hazardous Materials Safety Administration (PHMSA)’s deputy associate administrator for policy and programs. “Age also is a definite factor. Many pipelines were installed 40 years ago and have sharp turns where water which has separated from dilbit would tend to collect and start corrosion (Snow, Nick. 2012-07-24. “Diluted bitumen, heavy crudes are similar, NAS panel told.” Oil and Gas Journal. OGJ Washington Editor.).”

“Internal corrosion is a leading cause of pipeline failure — and one of the most difficult to detect.” Monitoring internal corrosion of pipelines is both “challenging and expensive” costing “several billion dollars annually in the U.S. alone.” Internal corrosion of pipelines can occur when moisture mixes with impurities (salts, like chlorine, and sulphur compounds). (source Bill Shaw, engineering professor at the University of Calgary and director of the Pipeline Engineering Centre, which studies corrosion and monitoring).

“Problems mainly arise when water that has not been removed from a crude before it goes into a pipeline begins to separate and collects at points along the bottom of the pipe’s interior, he explained. Dissolved gases—primarily carbon dioxide—and oil extracts such as organic acids also can influence corrosion rates, Moghissi said. Running a pig through the pipeline probably is the most effective corrosion inhibiter, although chemicals also can help, he told the panel.”

“Until the early 1980s, bitumen was trucked to asphalt reﬁners in Alberta and Saskatchewan. Growing volumes through the early 1980s supported the development of pipelines from producing areas to Edmonton, from where the bitumen could access high-conversion reﬁneries and broader asphalt markets. Between 1982 and 1985 Alberta Energy Company (AEC) built a pipeline system designed to move bitumen blend from Cold Lake to Edmonton and to ship diluent to Cold Lake from Edmonton (Walker, Ian C. 1998. “Marketing Challenges for Canadian Bitumen.” Imperial Oil, Calgary, Alberta, Canada).”

By 2003 there was concern that the transportation of crude bitumen would face huge obstacles. “Road conditions, weather problems, and fuel prices are some of the other issues that hauling companies have to deal with routinely. Although the preferred mode of transporting crude bitumen is pipelining wherever possible, the Alberta Utilities and Energy Board estimates that unless there is a dramatic technological breakthrough, or a substantial increase in the price of crude bitumen, pipelining of this product will not be technically or economically feasible within the foreseeable future (Laverty, K. 2003-04-07. “Super trucks: Loads grow so fast that the oil industry’s ‘transport architects’ stopped keeping score on size records.” Oilweek Magazine. Vol. 54. No. 14. page(s) 42-46).

Alberta Provincial Highway No. 63 built in 1970 is a 240-kilometre-long, two-lane north–south highway road connecting Fort McMurray and the Oil Sands bitumen mine sites to southern Alberta. According to Syncrude Canada, Highway 63 probably ferries the highest tonnage per mile of any road in Canada and is “inadequate for the traffic that uses it.” Plans are underway (2012) to expand it into a four-lane divided highway to accommodate the heavy traffic of logging trucks, SUVs, semi-trailers, buses and tanker trucks including convoys of extra-wide loads carrying tires, turbines and cokers (source). There are numerous fatal accidents on the highway as tankers and logging trucks slow traffic to a crawl while oil workers race to get in and out of the site. The expansion would cost c. one-billion-dollar and the province is considering using toll booths to place the cost of the oil sands’ driven needs on the shoulders of the users: the oil sands industry. This would increase the cost of trucking oil by tankers and intensify the push for more pipeline capacity.

“CN, in response to customer demand, is moving crude (i.e., heavy crude, light crude, pure bitumen) from areas in Western Canada to various markets,” it said in an emailed statement. “CN has also been providing truck-to-rail transportation solutions for crude oil, where CN is loading directly from truck to rail.”

Oil industry: not subsidies but federal and provincial incentives

The oil industry has received various forms of federal and provincial incentives in the years prior to the boom. For example, the governments provide funds for research on improved technologies and methodologies for extraction, land recovery, etc. Companies who receive this multi-million dollar funding are not obligated to use the technologies they develop if the profit-margins would be negatively affected by their implementation. How many millions of public funds have been quietly assigned to this research?

From where does Canada import its oil?

“Most Canadians are under the impression that we do not need to worry about our energy security. We see ourselves as a country rich in oil, and we assume that our own resources are available to us for consumption. That assumption is incorrect. Canadians do need to ask where their oil comes from because it doesn’t necessarily come from Canada! Canada imports more than half of the crude oil it needs. We purchase around 55 per cent of our oil from countries such as Algeria, Saudi Arabia and Venezuela. We are also turning increasingly toward new sources including Russian and African producers. Canadians should question whether we can count on those suppliers for a steady supply of oil (Council of Canadians).”

This debate unfolds at a time when Canadians consume about 1.8 million barrels of oil a day according to Peter Boag, president of the Canadian Petroleum Products Institute (Lindell, 2012-01-31). While Boag also claims that Canada’s 19 refineries produce two million barrels of day, and are only operating at 80% capacity, he neglects to mention that many Canadian refineries are older, smaller, inefficient and not designed for bitumen. The product Canadians produce is exported and Canada relies on U. S. refineries to supply gasoline and airline fuel for example. Eastern refineries rely on oil imported from Saudi Arabia, Africa and Venezuela, which are much more volatile than WTI prices for geopolitical reasons. In March 2012 the Brent-WTI differential continued to negatively impact the price of bitumen from the oil sands. Western Canada Select was priced at a $35.50 U. S. discount to West Texas Intermediate (WTI) (37% below the U.S. crude), which itself trades at a substantial discount to the Brent crude oil prices. Brent crude oil prices rose (2012-03-21) to a record high of near $125 per barrel (Hussain, Yadullah. 2012-03-21. “Oil industry may lose $18B a year in crude price discounts: CIBC.” Financial Post).

The market value of Western Canada Select

The inadequacy of the current pipeline national and Canada-U.S. networks also decrease the market value of Western Canada Select. Until TransCanada’s Keystone XL portion is operational, there is a bottle neck which limits the movement of bitumen to U.S. refineries capable of upgrading the heavy oil. Some predict that this pipeline extension will not be in place until late 2013 and until then the Brent-WTI differential will remain.

There is a request under review for a west-east reversal and expansion of the Seaway pipelines which would also positively impact the Alberta’s oil (Hussain, Yadullah. 2012-03-21. “Oil industry may lose $18B a year in crude price discounts: CIBC.” Financial Post.) “Ontario’s oil comes from Western Canada, but it is sent first to the United States to be refined before being delivered to the province.”

“The heightened pressure on lawmakers to get more revenue for Alberta’s bitumen follows recent calls to address a predicted decline in synthetic oil produced in the province, as a percentage of total bitumen output. The Energy Resources Conservation Board predicts 47% of bitumen produced in the province in 2020 will be upgraded to light oil, down from 58% in 2010. In 2008, the province had set a goal of 66%. The regulator’s summer forecast had some eyeing jobs and tax revenue attached to additional upgraders crying out for government actionPenty 2011-11-25.“

Synthetic Crude Oil Production: “In 2010, all crude bitumen produced from mining, as well as a small portion of in situ production (about 11 per cent), was upgraded in Alberta, yielding 46.1 million m3 (290 million barrels) of SCO. About 58 per cent of total crude bitumen produced in Alberta was upgraded in the province in 2010. By 2020, SCO production is forecast to almost double to 81.5 million m3 (513 million barrels). While this is a significant increase compared to 2010, it is expected that only 47 per cent of total crude bitumen produced in Alberta will be upgraded in the province by the end of the forecast period because of an expected narrow price differential of bitumen relative to light crude oil. Over the next 10 years, mined bitumen is projected to continue to be the primary source of the bitumen upgraded to SCO in Alberta. However, it is projected that bitumen from in situ production will be increasingly upgraded to SCO in the province. The portion of in situ production upgraded in the province will increase from 11 per cent in 2010 to 13 per cent by the end of the forecast period.” ERCB. 2011-06. “ST98-2011 Alberta’s Energy Reserves 2010 and Supply/Demand Outlook 2011-2020.” p. 6.

There is a call for keeping more employment in Canada and for expanded use of eastern oil refineries.

“A poll conducted by ThinkHQ Public Affairs showed 81% support in Alberta for the government taking steps to increase the amount of oilsands upgrading and refining done in the province, with the support cutting across partisan lines. The survey showed 73% support for the idea of putting higher royalties on the export of raw bitumen and 56% support for tax incentives for private investment. Support dropped under 50% for a Crown corporation to build and operate upgraders, operating subsidies to private sector upgraders and investing tax dollars to help build private sector projects (Wood 2012-01-26).”

Questions and concerns about the race to sell bitumen using today’s water-hungry and natural-gas hungry technologies, are being raised. There is a call to slow down the process. However, the price of natural gas has fallen dramatically and “natural gas is a key raw material for refineries, which use it predominantly as a source of fuel to operate. Hydraulic fracturing methods have significantly increased the supply of natural gas in the U.S.” “Natural gas is a market that has been turned upside down in the last few years with the development of technology for extracting gas from shale beds with hydraulic fracturing. The new resources made available through fracking have caused the price to drop from $8 for a million BTUs to between $4 and $5 per MBTU. The U.S. has been in the lead when it comes to exploiting shale gas (Kanellos 2011-06-09).

“In Natural Gas, U.S. Will Move From Abundance to Imports.” Canada is the only OECD nation that does not have a national energy plan which complicates the environmental and economic issues related to energy. Ever since Prime Minister Trudeau’s Energy Plan almost divided the country along the east-west axis, no Prime Minister has dared to touch the topic. In the Canadian system, provinces control energy while the federal government controls pipelines. Canadian cannot look to the risk-averse, profit-motivated oil industry to consider long-term resource development, investment of profits towards infrastructure beyond extraction, transportation and minor upgrading. It is only through federal-provincial and in some cases regional pressure that the oil industry could be pressured/encouraged to build oil refineries in Canada to develop an even more integrated oil industry. The federal government needs to take the lead. In March 2012 Alberta Premier Alison Redford began to discuss openly the possibility of a Canadian energy strategy as opposed to a national energy plan. Phase 4 of TransCanada’s Keystone pipeline project met major hurdles at the U. S. federal level in late 2011. Alberta Premier Alison Redford says her government will take a hands-off approach to the increased upgrading of bitumen in the province as Alberta’s oilsands production continues to ramp up (Wood 2012-01-26).”

“With the energy spotlight focused recently on the proposed Keystone XL and Northern Gateway pipelines that would ship raw bitumen to the United States and Pacific Coast, respectively, there have been growing calls for increasing the capacity in Alberta to upgrade and refine oilsands into products like synthetic crude, gasoline and diesel.” “Redford said it is up to the market and energy industry to determine opportunities for more processing (if it makes economic sense) — not the government. “If we have wheat, we’re not going to say to people you can only export bread.” “Redford remains committed to the planned North West upgrader, but there are no other projects in line for provincial involvement.”(Wood 2012-01-26).”

Even though “we would get far more value for our resources if we were to ship refined product,” Canada only refines about 50% of oil and the rest goes to refineries in the United States. Increases in oil refinery facility size and improvements in efficiencies have offset much of the lost physical capacity of the industry.

“The acquisition of Canadian companies by state-owned companies or sovereign wealth funds (whether from China, Russia or elsewhere), is a less clear-cut matter. Should Canada permit the nationalization of its business sector through foreign state ownership? … Yet, there are potential downfalls, particularly related to China National Offshore Oil Corp (CNOOC) being state-owned rather than a privatized business. Unless a government wishes its state-owned enterprises to operate strictly according to commercial criteria, a takeover of a private company by a State Owned Enterprise (SOE) could result in the target performing less efficiently since other criteria besides value maximization undermine profitability and productivity… recent papers published on both Canadian and international experiences conclude that state-owned enterprises perform less efficiently than privatized companies. .. The CNOOC takeover of Nexen will not be the last of similar potential acquisitions of Canadian businesses by foreign state-owned entities. Ottawa will need a clear policy to determine the suitability of these takeovers and to apply it readily.”

While it is widely acknowledged that Canada needs to diversify and depend less on the United States as its major market, there are concerns about basing the Asian market on state-owned corporations. The Economistrevealed some disturbing trends in this emerging form of capitalism: state capitalism. Sixteen of the largest twenty global oil companies are state owned, and together control over 80 % of oil reserves. Their bottom line is profit and have no concern for Canada’s long-term economic health, employment, environmental impact, etc.

CNOOK “is an $89 billion company with oil and gas assets in Indonesia, Iraq, Australia, Africa, North and South America, as well as China… The $15 billion bid by China National Offshore Oil Corp (CNOOC) to buy Canada’s Nexen, Inc will help the Chinese state giant gain the expertise to drill in deep, disputed waters of the South China Sea without relying on risk-averse foreign firms (Eckert, Paul. 2012-08-04. CNOOC-Nexen deal seen helping China’s South China Sea thrust. Reuters).” By 2018-2023 China would probably have the experience, knowledge and technologies like those Nexen already has to “set up and maintain stable rigs in 5,000-10,000 feet of ocean water” and “drill 10,000-18,000 feet deep in sediment (Eckert 2012-08-04)”. How might China’s access to an expanded South China Sea deep drilling, affect the future of oil sands bitumen market and the Northern Gateway pipeline in five or ten years?

Why does Canada not have a cohesive national energy strategy?

“Without a Canadian Energy Strategy – a strategy that will give Canadians security of their energy supplies, guaranteed access to energy reserves in times of need, and strong policies that protect our environment and focus on fi nding alternative, less harmful energy solutions – our country will continue to be a victim of an energy gold rush. Politicians cannot let corporations and the market set the agenda, focusing on big business needs, and privatizing public services, while ignoring the energy security needs of Canadians (Council of Canadians).”

We need a strong government position yet we do not have a cohesive energy strategy. The oil industry is a risk-averse industry and at this time there is an unwillingness to develop infrastructure beyond extraction and minimal upgrading. In the United States refineries are being closed. The proposed $6 billion Shell refinery was cancelled in 2009 because of “the current project execution environment, market conditions and the current inflationary pressures across the oil and gas industry.” Although greener technologies are being developed, it is estimated that we will continue to be dependent on fossil fuels until c. 2040. Why not stretch out our use of these invaluable resources? There are opportunities for job creation through the development and implementation of innovative marketable technologies that will make the extraction process more efficient, environmentally friendly and financially feasible? Federal funds have supported much research in the field that never sees the light of day because the oil industry, like the ocean liner, can’t adapt quickly to change. Enbridge is in the process of applying to the National Energy Board to reverse the flow in 35-year-old Line 9 Sarnia/Montreal pipeline to the original direction for which it was designed in 1975 to take western Canadian crude to Montreal refineries. “It would give Quebec and Atlantic Canada – which currently get 80 per cent of their crude from Europe, Africa and the Middle East – a reliable source of domestic oil. As Joseph Gargiso of the Communications, Energy and Paperworker’s Union said in support of the line reversal: “A country that is blessed with petroleum resources like Canada should first and foremost assure that the country as a whole has access to a guaranteed supply.” The pipeline reversal would also allow the Alberta oil industry to get a better price for its product (Calgary Herald 2012).”

“Canadians need a national energy strategy – one that puts citizens’ interests ahead of multi-billion-dollar oil companies. Right now, our country does not have a national energy strategy that addresses where our energy comes from, where it is going, or the high price of environmental devastation that comes with producing it. For nearly 20 years, Canada has lived with free trade agreements and free-market rules that are used to ensure that our energy resources keep fl owing out of the country with little or no direction from government. As one of the coldest countries on earth, Canada’s energy security is decided by the whims of the United States, the markets and the big oil companies.”

How many jobs do the oil sands provide?

Government of Alberta fact sheet (2011-02) entitled “Economic Activity in Alberta” claimed that, “Almost 139,000 Albertans [were] employed in Alberta’s mining and oil and gas extraction sectors. .. [O]n average over the next 25 years, oil sands are forecast by Canadian Energy Research Institute (CERI) to require more than 450,000 annual work positions across Canada. This totals more than 11.4 million person-years of employment.”
For example Husky has 4,380 permanent employees (Husky Annual Report 2010);

Why does Canada not have more oil refineries?

The Canadian Petroleum Products Institute (CPPI) commissioned The Conference Board of Canada study entitled “Canada’s Refining Sector: An Important Contributor Facing Global Challenges” . Pedro Antunes, (2011-10-31) argued that even if the upstream (oil and gas exploration and production) segment of the industry continues its robust expansion in Canada, “the future economic benefits, job creation, and profits from oil refining and processing are much less assured (Crawford, Todd. 2011-10-31. “Canada’s Refining Sector: An Important Contributor Facing Global Challenges.” The Conference Board of Canada. Commissioned by The Canadian Petroleum Products Institute (CPPI). 52 pages.

Document Highlights: Canada’s refining industry has undergone a massive restructuring over the past 30 years. Since the 1970s, the number of operating refineries has dropped from 40 to just 18 today. While global demand for petroleum products continues to rise and the outlook for Canada’s upstream energy sector is bright, Canadian refiners face a very particular set of challenges, since North American and other OECD markets will likely be characterized by declining demand.

Arguments for building more oil refineries in Canada

Increases in oil refinery facility size and improvements in efficiencies have offset much of the lost physical capacity of the industry.

Recent controversies surrounding the construction of pipelines to transport bitumen from the oil sands has raised questions about the reasons Canada does not develop a more integrated value-added industry. “We would get far more value for our resources if we were to ship refined product.”

Arguments against building more oil refineries in Canada

“In 2009 through 2010, as revenue streams in the oil business dried up and profitability of oil refineries fell due to lower demand for product and high reserves of supply preceding the economic recession, oil companies began to close or sell refineries. Due to EPA regulations, the costs associated with closing a refinery are very high, meaning that many former refineries are re-purposed (Wayman E. Recession’s latest victim: oil refineries. Earth magazine. June 2010. Pgs 10-11).In 2009 Royal Dutch Shell Europe’s largest oil company closed oil refineries in the US and considered selling or closing its 130,000-barrel-per-day refinery in Montreal, which it has operated since 1933.

Shortage of qualified labour

risk-averse industry

oil industry is closing refineries not constructing new ones.

multinational oil companies lack motivation to protect Canadian interests. 16 of the largest 20 global oil companies are state owned, and together control over 80 per cent of oil reserves. Canada had a state-owned oil company Petro Canada but it was acquired by Suncor.

government needs to take leading role in motivating oil industry to build oil refineries in Canada to develop integrated oil industry

high standards for environmental protection would be required in new constructions of oil refineries

International companies like Imperial Oil, Husky look at profits for global company. Integrated firms, such as Calgary-based Husky (controlled by Hong Kong billionaire Li Ka-shing) with its crude storage system in Hardisty, pipelines, upgrader and refineries, use the cheaper oil sands crude oil as refinery and upgrader feedstock. The stocks of these integrated firms are substantially mitigated. Husky’s net earnings increased by 22% since April 2011 in spite of the volatility of price of crude. Light and heavy Canadian crude varieties were steeply discounted against WTI in 2012 on pipeline bottlenecks in the U.S. Midwest, made worse by high production and refinery downtime (Calgary Herald 2012-04). The Calgary-based American integrated company, Imperial Oil, with its refineries posted a 30% increase in earnings in the first quarter of 2012 (Calgary Herald 2012-04).

MIT has argued for a liquid fuel converted from natural gas to replace gasoline. “[T]he chemical conversion of natural gas into some form of liquid fuel may be the best pathway to significant market penetration in the transportation sector (MIT 2011).”

Kearn oil sands project: “The product will be transported to market through a pipeline system. Imperial and ExxonMobil own extensive refinery infrastructure in Canada and the U.S. that could receive bitumen or upgraded feedstock to make a variety of refined products. Production may also be sold to third parties. Any future upgrading capacity to support the Kearl project would be the subject of separate application.”

Multinationals are not concerned about Canadian economy

1990s mergers created companies that have more market power

loss of competition

Athabaskan oil sands are extra heavy and high in sulphur involving most complex and expensive refining processes

green movement has oil sands under microscope

oil refineries are major polluters in themselves

oil industry has market power so control of oil refinery production can affect gasoline prices etc

weak anti-trust laws

poor global economic conditions

Albertan oil industry promises revenue and employment

it is costly to build an economically oil refinery that passes environmental standards

How much does it really cost to build a brand new and economically viable oil refinery?

The estimated cost of the Wallaceburg, Ontario oil refinery proposed by Shell Canada in 2007 was between $6 billion and $8 billion. The projections were for the employment of 700 people once operational and thousands of jobs during construction. The project was cancelled c. 2009 because of “the current project execution environment, market conditions and the current inflationary pressures across the oil and gas industry.” Is there more of a financial benefit to Canada to see raw bitumen? Cooper, Mark. 2003-10. “Spring Break in the US Oil Industry: Price Spike, Excess Profits and Excuses.”

Among others, Canadian oil sands are being developed by supermajors, the world’s five or six largest publicly-owned oil and gas companies: BP p.l.c., Chevron Corporation, ExxonMobil Corporation, Royal Dutch Shell plc, Total S.A. and ConocoPhillips Company A supermajor is one of the world’s five or six largest publicly-owned oil and gas companies. In an effort to improve economies of scale, hedge against oil price volatility, and reduce large cash reserves through reinvestment, largely in response to the a severe fall in oil prices the major mergers and acquisitions of oil and gas companies took place between 1998 and 2002. (BP’s acquisitions of Amoco in 1998 and of ARCO in 2000; Exxon’s merger with Mobil in 1999, forming ExxonMobil; Total’s merger with Petrofina in 1999 and with Elf Aquitaine in 2000, with the resulting company subsequently renamed Total S.A.; Chevron’s acquisition of Texaco in 2001; and the merger of Conoco Inc. and Phillips Petroleum Company in 2002, forming Conoco Phillips.
This process of consolidation created some of the largest global corporations as defined by the Forbes Global 2000 ranking, and as of 2007 all were within the top 25. Between 2004 and 2007 the profits of the six supermajors totaled US$494.8 billion (wiki)

Reductions in storage capacity and the number of gasoline stations of over ten percent have also taken place in just the past half-decade. These reductions in capacity have been driven in part by a merger wave that has resulted in a significant increase in the concentration of ownership of refinery capacity and gasoline outlets. Four-fifths of regional refinery markets have reached levels of concentration that trigger competitive concerns, even by the standards adopted by the antitrust division of the Reagan administration’s Department of Justice. In these markets, the largest four firms account for at least one-half and as much as three quarters of the refined product output. A similar trend has been in evidence at the level of gasoline stations.

“In 1990, 22 integrated companies covered an average of 28 states. In 1999, 17 companies covered an average of 26 states.” (Gilbert and Hastings, p. 27; see also Hastings, Justine, “Vertical Relationships and Competition in Retail Gasoline Markets: Empirical Evidence from Contract Changes in Southern California,” Competition Policy Center, 2000.) “The rule of thumb reflected in all iterations of the Merger Guidelines is that the more concentrated an industry, the more likely is oligopolistic behavior by that industry…. Still, the inference that higher concentration increases the risks of oligopolistic conduct seems well grounded. As the number of industry participants becomes smaller, the task of coordinating industry behavior becomes easier. For example, a ten-firm industry is more likely to require some sort of coordination to maintain prices at an oligopoly level, whereas the three-firm industry might more easily maintain prices through parallel behavior without express coordination (U.S. Department of Justice and Federal Trade Commission Horizontal Merger Guidelines, 1997, at section 0.1.).”

Where is oil found in Canada?

“Not surprisingly, the biggest Canadian producer is the province of Alberta, which accounts for two-thirds of Canada’s production. Saskatchewan is next at roughly 18 per cent, and Newfoundland produces 13 per cent with its off-shore resources. Manitoba, Ontario, British Columbia and the Northwest Territories round out Canadian output with a combined share representing 2.8 per cent of production (Council of Canadians).”

Where does Canadian crude oil and petroleum products go?

66% of Canada’s oil production goes almost exclusively to the United States in the form of exports (Council of Canadians).

How many oil refineries does Canada have in 2012?

“The refining, distribution and marketing of transportation fuels industry operates through an infrastructure with close to 100,000 employees. The industry’s infrastructure in Canada includes 19 refineries in 8 provinces, a complex network of 21 primary fuel distribution terminals, 50 regional terminals and 12,000 retail service stations ( The Canadian Petroleum Products Institute (CPPI) 2011 ).”

“Canada is home to 18 refineries, 16 of which are operated by Canadian Petroleum Products Institute (CPPI) members and represent the majority of the country’s refining capacity. CPPI claims Canada is a net exporter, mainly to the United States, of refined petroleum products and crude oil.” However, Canada imports most of its refined fuel from the United States. “Eastern Canada relies on imported oil — despite the fact that some provinces are oil producers. There are several offshore drilling operations in Newfoundland and Labrador, but none of the oil is actually used in Canada. The eastern provinces rely on an oil supply that’s imported from Saudi Arabia, Africa and Venezuela (CBC. 2012-01-25.”

Where are the existing oil refineries in Canada?

British Columbia

Husky Energy Inc. Prince George Refinery, Prince George BC.”Husky’s U.S. refining operations process a mix of different types of crude oil
from various sources but are primarily light sweet crude oil at the Lima, Ohio Refinery and approximately 50% heavy crude oil
feedstock at the Toledo, Ohio Refinery. The Company’s refined products business in Canada relies primarily on purchased refined
products for resale in the retail distribution network. Refined products are acquired from other Canadian refiners at rack prices or
exchanged with production from the Husky Prince George Refinery (Husky Annual Report 2011).” Husky is controlled by Hong Kong billionaire Li Ka-shing.

Saskatchewan

Nova Scotia

Imperial Oil Limited Dartmouth Refinery Dartmouth NS

Newfoundland

North Atlantic Refining Limited Come by Chance Refinery Come by Chance NF. North Atlantic Refining Limited is a downstream subsidiary of Harvest Operations Corporation which is a wholly-owned subsidiary of the Korean state-owned Korea National Oil Corporation (“KNOC”). The Korea National Oil Corporation, whose CEO is a KNOC executive who replaced is a “significant operator in Canada’s energy industry offering stakeholders exposure to an integrated structure with upstream (exploration, development and production of crude oil and natural gas) and downstream (refining and marketing of distillate, gasoline and fuel oil) segments. [] KNOC Upstream oil and gas production is weighted approximately 70% to crude oil and liquids and 30% to natural gas, and is complemented by their long-life refining and marketing business.” The replacement in 2012 of a Canadian CEO by a Korean CEO is considered to be a major paradigm shift in the Asian-Canadian oil investment partnerships.

NOVA Chemicals (Canada) Limited Sarnia ON “NOVA Chemicals’ Corunna site The Corunna facility started up in late 1977 and was purchased by NOVA Chemcals in 1988. It was the first fully integrated refinery and petrochemical complex in North America. It is a refinery and petrochemical complex that supplies between 30% and 40% of Canada’s total requirements for primary petrochemicals. The refinery is capable of producing in excess of 3.5 billion pounds (1.6 million tonnes) of basic petrochemicals and 3 billion pounds of refinery and energy products annually. The Corunna site processes crude oil, condensate and natural gas liquids (NGLs) that are delivered to the site by pipeline from western Canada. These products are the feedstocks used to manufacture ethylene, propylene, butadiene, iso-butylene, n-butylene, benzene, toluene and xylene. During petrochemical production, other co-products are also manufactured, including synthetic natural gas, liquefied petroleum gas, gasoline components, diesel fuel, home heating oil and heavy residual fuel oil. ” 500 employees work at the Corunna plant.

February 26, 2015

There are major challenges in locating reliable sources of useful, comprehensible information on the oil industry. The following sources are not necessarily neutral. Wikipedia entries on concepts and organizations related to the oil industry constantly include warnings to readers that the entries may not be neutral and indeed reflect advertisement more than unbiased, information based on reliable sources. Citations often lack references.**

The original post dated 10 November 2011 was updated until 2012. Beginning with more recent events in 2015, I am compiling the webliography, chronology of events, etc in separate posts.

Webliography and Bibliography

There are major challenges in locating reliable sources of useful, comprehensible information on the oil industry. The following sources are not necessarily neutral. Wikipedia entries on concepts and organizations related to the oil industry constantly include warnings to readers that the entries may not be neutral and indeed reflect advertisement more than unbiased, information based on reliable sources. Citations often lack references.**

2012-01-21. “The rise of state capitalism.” The Economist.”The spread of a new sort of business in the emerging world will cause increasing problems … [T]he world’s ten biggest oil-and-gas firms, measured by reserves, are all state-owned. State-backed companies account for 80% of the value of China’s stockmarket and 62% of Russia’s. And they are on the offensive.”

“Continuing the high standards set by earlier editions, Petroleum Refining, Fourth Edition summarizes recent developments in oil refining processes, addressing topics ranging from basic applications to the implementation of viable operations that meet environmental and economic requirements. The authors maintain the clear, systematic style that made previous editions so popular. This edition reviews petroleum-refining technology and refining processes, incorporates recent statistics on utility data, investment, and operating costs, and considers environmental factors, the place of reformulated fuels in product distribution, and uses for heavier crude oils and those with higher sulfur and metal (Review).”

“A rapidly expanding oil sands industry and a dwindling supply of feedstock for Alberta’s ethane-based petrochemical industry have stimulated interest in evaluating bitumen for producing a broad slate of refined products, including petrochemicals. Two industry/government studies evaluated different process schemes for integrating oil sands, refining, and petrochemical operations and convert heavy gas oils into both refined products and petrochemicals. Since market demand for fuels and refined products far exceeds that for petrochemicals, the performance characteristics of the heavy oil conversion processes are important to optimize the volume ratios of the products to meet market volume demands. The paper reviews different heavy oil processing technologies focusing on olefin to fuel product ratios and flexibility to change these ratios. The review includes conventional noncatalytic thermal (steam) cracking, as well as catalytic processes. These technologies are at different stages of commercial development for production of fuels and olefins, and must be evaluated and adapted to meet Alberta’s aromatic bitumen-derived heavy gas oils. Work is underway in an industry/government study towards developing an integrated process for the combined production of refined fuels and petrochemical feedstocks. In addition, two workshops were held in February 2005 to address the business and regulatory gaps that needed to be addressed before such a process can be commercialized; the results from the workshops will also be discussed in the paper (Laureshen, Clark and Du Plessis 2005:15).“

“Introduction: Alberta has an enviable position as a North American energy hub, providing oil and gas to United States markets through an extensive pipeline network. In addition to conventional oil and gas, Alberta has large reserves of coal and coal bed methane, as well as the massive oil sands deposits that underlie 140,800 square kilometres of the province. The oil sands have outstripped conventional oil reservoirs as the primary source of oil in the province. According to the Alberta Department of Energy, production of bitumen and synthetic crude oil was close to 158,987.3 million m3/d (one million BPD) in 2003, as opposed to 100,162 m3/d (630,000 BPD) of conventional oil production. If all new projects, and expansions to existing projects currently planned, take place as scheduled, Alberta’s bitumen production is expected to triple by the year 2030. However, the continued expansion of Alberta’s oil sands faces significant challenges. Diluent availability is already a problem, water use is facing restrictions, and natural gas is becoming more costly and less available. A further problem is the ability of Canadian and U. . . . (Laureshen, Clark and Du Plessis 2005:15).“

October 12, 2014

French Lilacs

French lilacs

French lilacs

Caragana

Bearded Iris

Shasta Daisies

It wasn’t Gehl himself, but someone dressed in black from his consultancy firm, hired by the developer. They stood on the street and studied the block-long lane way, shaded by overgrown Caragana and French lilacs. I remember thinking that I was pleased the bearded Irises, that bordered the north-side of the lane, were in bloom. At the community association meeting when his name was first mentioned, I could not quite believe it. But there they were four days later. Could this little stretch of pot-holed lane in a city known for its passionate embrace of large and/or powerful vehicles, become a canvas for an urban project inspired by Gehl?

A few years earlier, for a number of different reasons, I had begun reading as much as I could on complex interlinked issues and concepts such as affordable housing, densification, walkability, new urbanism, etc. Gehl’s name appeared in many of the documents I was reading. His influence in the real world, not just in theory was visible in many urban spaces.

Jane Jacobs (1961) had critiqued the Post WWII urban rationalist modernist planning policy which drove urban renewal projects that separated city areas based upon usage-commercial, industrial and residential (Flint 2009). She focused specifically on Robert Moses and other city planners like him who favoured cars over people.

“Moses] was responsible for 13 bridges, 2 tunnels, 637 miles of highways, 658 playgrounds, 10 giant public swimming pools, 17 state parks and dozens of new or renovated city parks (Flint 2009 cited in Garner 2009).”

It was very personal. In the 1930’s when Jacobs moved from Pennsylvania to New York she chose to live in Greenwich Village, a neighbourhood which at that time had,

“storefronts with awnings shading cluttered sidewalks, kids chasing one another in front of a grocery, delivery trucks stopping and starting their way up the street.” Although the midtown skyscrapers and the cluster of financial district tall buildings were visible from Greenwich, most of the Greenwich buildings were simple, two or three stories-high with a few with five or six stories (Flint 2009).

“Everywhere she looked she saw people-people talking to one another, it seemed, every few feet, casually dressed women window-shopping, old men with hands clasped on canes sitting on the benches in a triangular park. Everyone looked, she thought, the way she felt: unpretentious genuine, living their lives. This was home (Flint 2009).”

As they perused the lane way I was already enjoying infusions of rose petals, stevia and cat mint from the garden on the other side of the lane way of the lot, the proposed site of 24 luxury condos. I had thought of offering them some but mentally calculated how much such a consultancy cost an hour or a minute. Months later with architectural drawings in place, the reality of the construction taking over the sun-filled empty lot noisy with gossipy house sparrows, magpies and squirrels, sinks in little by little.

July 21, 2013

Originally published by Maureen Flynn-Burhoe, on 8 June 8, 2011 on my social histories timelines that I will be eventually deleting.

“Coal remains a key component of Canada’s diverse energy supply picture, accounting for as much as 20% of electricity generation. Six of Canada’s provinces rely to some degree on coal to supply electrical power, with three (Nova Scotia, Saskatchewan and Alberta) almost fully reliant (NRCAN 2010).”

Coal-fired power stations are major emitters of CO2, the most important greenhouse gas (GHG). Brown coal emits 3 times as much CO2 as natural gas, black coal emits twice as much CO2 per unit of electric energy. “Emissions of sulphur dioxide (SO2) and nitrogen oxides (NO and NO2) have traditionally been the main concern. Proven technologies, such as flue gas desulphurisation, selective catalytic reactors, low NOxburners and fluidized bed combustion, are available – albeit at a cost – to reduce these emissions. Recently, pending legislation on air toxics, especially mercury, on fine particulates, and on GHG emissions has emerged as a more formidable challenge. Canada’s GHG emissions from electricity generation in 2004 were 130 Mt. The overwhelming proportion, about 75%, was from the use of coal (NRCAN 2010).”

The world’s power demands are expected to rise 60% by 2030.[5] With the worldwide total of active coal plants over 50,000 and rising,[6] the International Energy Agency (IEA) estimates that fossil fuels will account for 85% of the energy market by 2030.[5]

The ﬁve largest power plant sources of NOx in Canada are coal plants in Alberta, Ontario and Saskatchewan. The large emitters in Canada are mainly coal plants located in central Alberta, southern Saskatchewan, southern Ontario, New Brunswick, and Nova Scotia. New Brunswick and Newfoundland also have one oil-ﬁred plant each with large SO2 emissions. The 60 highest mercury-emitting power plants in the United States (or 18 percent of the those listed in Table 3.9) produced 50 percent of the total annual emissions from such facilities. Fourteen facilities produced 90 percent of the power plant mercury emissions in Canada, with annual emissions ranging from 275 kilograms to 1.0 kilogramIn Canada, the highest emitting facility produced 14 percent of the total annual emissions from the Canadian electricity sector (CEC 2004).

Mercury is a toxic substance that accumulates in the environment. Mercury emissions from power generation result from the combustion of coal, which
contains mercury. These emissions can be deposited locally and transported throughout the globe. Canada deposits 9 T of mercury but receives 100 T of emissions. Mercury emissions from coal-ﬁred power plants in North America are generally unregulated, although efforts are underway in Canada and the
United States to develop control programs. For example, Alberta adopted a reduction target of 50 percent from 2003 power plant mercury emissions
by the end of 2009.

“Mercury control technology is highly efficient and available for all coal types. Activated Carbon Injection (ACI) is the primary technology being used to reduce mercury emissions from new and existing coal plants. Data from power plants shows that the tested boilers achieved, on average, reductions in mercury emissions of about 90 percent. (2011-03. Mercury Alert: Cleaning up Coal Plants for Healthier Lives).”

Who’s Who

Canada

Carbon Management Canada (CMC)

Secretariat of the Commission for Environmental Cooperation (CEC) of North America (SO2, NOx, mercury, CO2) “Consortia of companies, like the Canadian Clean Power Coalition or the Clean Energy Group in the United States, are coming together to promote the production and use of alternate or renewable energy sources. Other companies are partnering with counterparts in developing countries to create Clean Development Mechanisms (CDMs) that will help to address the looming threat of global warming. In a similar vein, several states and provinces have set in place or are contemplating ﬁrm commitments to signiﬁcantly reduce mercury emissions at coal power plants in the next several years (e.g., Alberta, Connecticut, Massachusetts, New Jersey, and Wisconsin).” This report includes lists of power plants and their emissions (2002 statistics).

Clean Air Strategic Alliance (CASA) was established in March 1994 as a new way to manage air quality in Alberta. CASA is a multi-stakeholder partnership. It is composed of representatives selected by industry, government and non-government organizations. Every partner is committed to a comprehensive air quality management system for Alberta.

A timeline of selected events related to the social history of high-emitting coal-fired plants

2025 33 of 51 of Canada’s coal-fired plants will reach the end of their economic lives.

2011-06-08. “Coal Comfort: EPA Cracks Down on the U.S.’s Dirtiest Mercury-Emitting Power Plants” Scientific American. “Twenty of the top 25 mercury-emitting coal-fired utilities in the U. S. are located within 80 to 160 kilometers of some of the largest metropolitan areas in the nation.”

2011 Canada’s Environment Minister Jim Prentice had promised to firm up new standards to force electricity producers to phase out older, high-emitting coal-fired plants and require newer facilities to match the emissions of gas fired plants.

2011-04-26 The Saskatchewan government through SaskPower is moving ahead with their Carbon Capture and Sequestration (CCS) project into $1.2-billion retrofit of Boundary Dam generating station. The $1.2-billion project will rebuild one of its old coal power plants to pump its greenhouse gas emissions underground. The new CCS clean coal power plant is the first of its kind and size anywhere in the world. The project is located at the Boundary Dam Power Station, Estevan and it will be completed in 2013 – 2014 (Leader Post).”

The project will be the world’s first commercial CCS system and it will capture an estimated 1 million tons of CO2 emission per year. That is equivalent to taking 200,000 vehicles off the road.

2011-03-22 The Government of Canada contributed an additional $899,000 in funds to a Carbon Management Canada (CMC) gasification project in Regina, Saskatchewan (Carbon Management Canada).

2011-03 Coal-fired power plants are the primary source of toxic mercury air emissions in the U.S. Mercury pollution contaminates our land and waters, causing serious human health impacts… [T]he top emitters of mercury in the U.S. (25 coal-fired plants) contribute nearly a third of all mercury emissions from the electric sector while only providing 8% of U.S. electricity. Nearly half of all U.S. river-miles and lake-acres were under water contamination advisories. This includes 100% of Great Lakes Coastal Waters Lake Acres. Eighty percent of all water contamination advisories in the U. S. were issued because of mercury contamination. (2011-03. Mercury Alert: Cleaning up Coal Plants for Healthier Lives).

2010-06-23 Canada’s Environment Minister Jim Prentice promised to phase out older coal-fired power plants to cut the country’s greenhouse gas emissions, moving toward gas fired plants. According to Prentice: “Our regulation will be very clear. When each coal-burning unit reaches the end of its economic life, it will have to meet the new standards or close down. No trading, no offsets, no credits.” The measure is expected to reduce greenhouse gas emissions in the country by 15 megatonnes. Along with the proposed regulations, Prentice also announced the government would contribute C$400 million ($384 million) for its share of a fund set up under the Copenhagen accord to help impoverished countries cope with climate change.

2010-10-14 “Coal remains a key component of Canada’s diverse energy supply picture, accounting for as much as 20% of electricity generation. Six of Canada’s provinces rely to some degree on coal to supply electrical power, with three (Nova Scotia, Saskatchewan and Alberta) almost fully reliant (NRCAN).”

2009 “Since 1999, mercury air emissions from U.S. coal-fired power plants have decreased by almost 27 percent: from over 48 tons in 1999 to 35 tons in 2009 (2011-03. Mercury Alert: Cleaning up Coal Plants for Healthier Lives).”

Abstract: “Alberta stakeholders, through the Province’s Clean Air Strategic Alliance (CASA), identified mercury as the pollutant of highest priority for control from coal-fired power plants. Working with CASA, the Province finalized a new Mercury Emission from Coal-Fired Power Plants Regulation [Mercury Emissions From Coal-fired Power Plants Regulation, March 2006, Alberta Regulation 34/2006, Alberta Queen’s Printer, Regulation may be found at http://www.gov.ab.ca/qp.%5D [1]. The regulation places the province at the forefront of controlling mercury emissions from the sector on a global level by driving actions to reduce mercury emissions from existing coal-fired power plants in the province by at least 50% by 2010. Requirements also include continuous improvement provisions for further mercury reductions beyond 2010 based on technology advancement over the next 10 years. This paper summarises the regulation, the work the province undertook at the provincial and national level in its development, and status of implementation actions.”

2009 Alberta electricity companies, “TransAlta, ATCO, and EPCOR, teamed with GE Energy to conducted full-scale evaluation of sorbent injection in Sundance Unit 5 operated by TransAlta. Sundance Unit 5 fires a Western Canadian sub-bituminous coal and is equipped with cold-side ESP for PM control. Goals of the program were to evaluate: (1) the ability of achieving 70% or greater mercury reduction using activated carbon injection in long-term tests (30 days), (2) the effect of sorbent injection on ESP performance and opacity in long-term testing, and (3) the effects of combustion conditions on “natural” mercury removal in fly ash. DARCO Hg-LH was injected upstream of ESP at average injection rate of 2.1 lb/MMacf and achieved an average mercury removal of 80%. During the test, the sorbent injection rate was varied from 0.55 lb/MMacf to 8 lb/MMacf with mercury removals from 65% to > 95%. The continuous 30-day DARCO Hg-LH injection testing demonstrated that 70% mercury removal could be achieved at DARCO Hg-LH injection rate of 1.2 lb/MMacf. Tests were conducted to optimize combustion conditions to improve “native” mercury capture in the fly ash. Testing demonstrated that combustion conditions that resulted in reduction of NOx emissions also corresponded to reduced mercury emission. Mercury emissions were reduced by up to 50% and NOx emissions by up to 35% from baseline levels as a result of changes in the way Unit 5 operated. Integration of sorbent injection with combustion conditions reduced requirements for sorbent injection by 20–30%. Testing has demonstrated that sorbent injection did not have an effect on opacity and ESP performance. Keywords: Mercury; Sub-bituminous coal; Activated carbon; Sundance 5; Cold ESPs.”First full-scale demonstration of mercury control in Alberta.”

2008 Collectively, power plants were responsible for 72 percent of mercury air emissions in the U.S. (2011-03. Mercury Alert: Cleaning up Coal Plants for Healthier Lives).

2008-08-21 Saskatchewan Power Corporation (SaskPower) studied a Clean Coal Project. The intention would be to build a coal-fired plant that would effectively capture all carbon dioxide emissions. The cost of such a plant was so high that SaskPower decided to not construct such a plant until later. Instead the required capacity will be obtained from power plants fuelled by natural gas. It would have been The first coal-fueled plant capable of capturing and burying carbon dioxide. Canada, had committed C$1.4 billion ($1.34 billion) on the plant planned to incorporate oil recovery in the plans to offset costs, a different approach than the U.S., which canceled a similar plant in 2007 (Whitten:Canada to Move Ahead on `Clean-Coal’ Plant After U.S.’s Fails.)”

Abstract: “Alberta stakeholders, through the Province’s Clean Air Strategic Alliance (CASA), identified mercury as the pollutant of highest priority for control from coal-fired power plants. Working with CASA, the Province finalized a new Mercury Emission from Coal-Fired Power Plants Regulation [Mercury Emissions From Coal-fired Power Plants Regulation, March 2006, Alberta Regulation 34/2006, Alberta Queen’s Printer, Regulation may be found at http://www.gov.ab.ca/qp.%5D [1]. The regulation places the province at the forefront of controlling mercury emissions from the sector on a global level by driving actions to reduce mercury emissions from existing coal-fired power plants in the province by at least 50% by 2010. Requirements also include continuous improvement provisions for further mercury reductions beyond 2010 based on technology advancement over the next 10 years. This paper summarises the regulation, the work the province undertook at the provincial and national level in its development, and status of implementation actions.”

Emissions from coal-fired plants in general

Fact sheet

Coal-fired power plants are responsible for almost three-quarters (35 tons) of all mercury air emissions in the U.S. (2011-03. Mercury Alert: Cleaning up Coal Plants for Healthier Lives).

January 8, 2013

Via Flickr:
The National Gallery of Canada gradually became morphed into my memory palace, a mnemonic device where social histories began to reveal themselves as one perspective merged into another. Renaissance perspective was too linear, too Hegelian for the way in which I wanted to revisit communal memories. I began to see the gallery spaces through an Escherian perspective where each art work opened into a panorama, a vista of social histories.